During hydraulic fracturing operations, operators want to minimize the number of trips they need to run in a well while still being able to optimize the placement of stimulation treatments and the use of rig/fracture equipment. Therefore, operators prefer to use a single-trip, multistage fracing system to selectively stimulate multiple stages, intervals, or zones of a well. Typically, this type of fracturing systems has a series of open hole packers along a tubing string to isolate zones in the well. Interspersed between these packers, the system has fracture sleeves along the tubing string. These sleeves are initially closed, but they can be opened to stimulate the various intervals in the well.
For example, the system is run in the well, and a setting ball is deployed to shift a wellbore isolation valve to positively seal off the tubing string. Operators then sequentially set the packers. Once all the packers are set, the wellbore isolation valve acts as a positive barrier to formation pressure.
Operators rig up fracturing surface equipment and apply pressure to open a pressure sleeve on the end of the tubing string so the first zone is treated. At this point, each fracture sleeve needs to be actuated so fluid can be diverted to flow outwards to fracture the zones of the well. The actuation must be performed in a sequential manner to allow the borehole to be progressively fractured along the length of the bore, without leaking fracture fluid out through previously fractured regions.
Due to the expense and frequent failure of electronic or electrical devices downhole, the most common approach to actuate the sleeve is still fully mechanical. Operators treat successive zones by dropping successively increasing sized balls down the tubing string. Each ball opens a corresponding sleeve so fracture treatment can be accurately applied in each zone.
The sleeves are configured so that the first dropped ball, which has the smallest diameter, passes through the first and intermediate sleeve, which have a ball seat larger than this first ball, until it reaches the furthest away tool in the well. This furthest away sleeve is configured to have a ball seat smaller than the first dropped ball so that the ball seats at the sleeve to block the main passage and cause ports to open and divert the fluid flow.
Subsequently dropped balls are of increasing size so that they too pass through the nearest sleeves but seat at a further away sleeve that that has a suitably sized seat. This is continued until all the sleeves have been actuated in the order of furthest away to nearest. As is typical, the dropped balls engage respective seat sizes in the sleeves and create barriers to the zones below. Applied differential tubing pressure then shifts the sleeve open so that the treatment fluid can stimulate the adjacent zone. Some ball-actuated sleeves can be mechanically shifted back into the closed position. This gives the ability to isolate problematic sections where water influx or other unwanted egress can take place.
Although this still remains the most common technique, this approach has a number of disadvantages. Because the zones are treated in stages, the smallest ball and ball seat are used for the lowermost sleeve, and successively higher sleeves have larger seats for larger balls. Due to this, practical limitations restrict the number of balls that can be run in a single well. Because the balls must be sized to pass through the upper seats and only locate in the desired location, the balls must have enough difference in their sizes to pass through the upper seats. Accordingly, the number of sleeves with varying ball seats that can be used is limited in practice because there must be a significant difference in the size of the seat (and therefore the ball) so that a given ball does not inadvertently actuate a previous sleeve or get pushed through its seat when pressure is applied.
In addition, the seats act as undesirable restrictions to flow through the tubular. The smaller the seat is; then the greater the restriction is. Overall, when stimulating zones through fracturing and then producing, operators want to have a larger bore through as much of the tubing string as possible because it allows for a better production rate. In a typical multistage system of fracturing sleeves, the bore through the tubing string restricts fluid flow due to the different sized restrictions from the various fracturing sleeves. Thus, the system is restricted to a range of internal dimensions for optimum production rate.
To overcome difficulties with using different sized balls, many service companies still use the typical ball and seat approach, but they have sought to optimize the size differences between the different balls and seats. Additionally, multi-stage systems have been developed that utilize one ball size throughout an arrangement of stimulation sleeves.
In other implementations, some operators have used selective darts that use onboard intelligence to determine when the desired seat has been reached as the dart deploys downhole. An example of this is disclosed in U.S. Pat. No. 7,387,165. Moreover, operators have used smart sleeves to control opening of the sleeves. An example of this is disclosed in U.S. Pat. No. 6,041,857. Electronic systems, such as RFID systems, can be used to selectively actuate the sleeves, but these can be complex, expensive, and subject to unique forms of failure. Indeed, forms of electrical, electronic, or magnetic devices may not be robust enough to withstand the harsh downhole environment.
Even though such systems have been effective, operators are continually striving for new and useful ways to selectively open sliding sleeves downhole for fracture operations or the like. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.